Insulation-liquid-filled electrical equipment, such as oil-filled shunt reactors, bushings, and especially transformers such as power and distribution transformers, are filled with insulation liquid, in particular oil, for cooling and electrical insulation purposes. Faults inside the electrical equipment as well as degradation of the insulation liquid and of other insulation components such as insulation paper provided within the electrical equipment can form decomposition gasses which mainly dissolve into the liquid. This is valid for equipment employing both mineral oil and oil from natural sources.
It is important to detect such faults, errors and degradations early, since especially transformers are important components of the electrical grid, and their failure can be very costly. Hence, a transformer is supposed to operate continuously and as error-free as possible over many years or even decades.
The quantity and composition of the decomposition gases is dependent on the underlying defect: A large fault with high energy content, such as rapid overheating or arcing, causes large amounts of gas to be produced in a short period of time, whereas the amount of gas produced by a small fault may be relatively smaller. Also, the relative concentrations of the different gasses dissolved might indicate the specific type of fault. Thus, if the nature and amount of individual gases dissolved in the insulation liquid are known, the occurrence of a change of the concentration of a specific gas in the oil can be used to identify an electrical fault in the equipment. It is known that one of the most important indicators for electrical failure in oil insulated transformers is the occurrence of hydrogen gas dissolved in the oil, which is for example produced at a faulty portion of an insulation of a winding of the transformer by thermal or electrical decomposition of the oil. For this reason, it is desirable that such errors, which may eventually cause complete failure of the transformer, can be detected as early as possible by identifying a rise in hydrogen concentration. This should ideally be possible at a stage when appropriate counter-measures may still be taken before serious and potentially costly malfunction occurs.
At a very early stage of such an electrical fault, only a very small amount of hydrogen gas may be produced, which dissolves in the oil and thus a concentration of dissolved hydrogen builds up in the oil over a longer period of time—whereby the hydrogen concentration in the oil may, at least during an early phase of the failure, even be below a threshold at which it can be detected with most known detection methods.
Most modern electrical transformers in power grids are still not equipped with on-line or real-time monitoring devices for such gasses. In order to control and evaluate the health of these transformers, an oil sample from the insulating oil bath is periodically taken and sent to qualified laboratories where the dissolved gases and other oil properties are measured. This monitoring method is time consuming, lacks continuity, has the risk of human error and is highly priced. Even if this costly method is carried out more frequently, there are several possible sources for error in the process, for example changes in the chemical and physical properties of the probe during the transport between the point in time when the probe is drawn, and the moment when the gas content is actually determined in a laboratory. Also, this method does not provide any information on where a fault occurred in the transformer. Thus, this method shall be of no further interest here, even though it is still widely used.
On the other hand, in online-methods the gas concentration in the insulation liquid is monitored directly and (quasi-)continuously. For this purpose, monitoring systems exist, sometimes built-in, for measuring hydrogen in transformer oil. These systems are based on different sensing techniques. They include, for example, semiconductor sensors, thermal-conductivity analyzers, pellistors, and fuel cell sensors, amongst others. These sensing techniques usually require a complicated gas separation system that adds complexity and cost to the sensor design and calibration. Thus, these devices are generally cumbersome and expensive. Additionally, some of these monitoring techniques suffer from cross-sensitivity towards other gases present in the oil, which additionally makes the results less reliable.
Therefore, even advanced transformers, i.e. those equipped with a dedicated on-line gas monitoring system, are often still additionally and periodically verified with expensive laboratory tests to reassure the accuracy of the on-line gas monitoring system.
There have been proposals for such on-line hydrogen monitoring devices which include thin film based fiber optical sensors, wherein a sensing material changes its optical properties upon an exposure to hydrogen dissolved in the oil. One such system for detecting hydrogen gas is described as an optical switching device in WO 2007 049965 A1. Another proposal is provided in “Optical fiber sensor for the continuous monitoring of hydrogen in oil” by T. Mak, R. J. Westerwaal, M. Slaman, H. Schreuders, A. W. van Vugt, M. Victoria, C. Boelsma, B. Dam, in: Sensors and Actuators B 190 (2014) 982-989. Thereby, the proposed optical sensors include a sensitive film comprising, for example, an alloy of Mg and Ti, capped with a Pd-containing layer. For the hydrogen detection, metal hydrides thin films can be used since they change their optical (and also electrical) properties upon exposure to hydrogen.
The kinetics as well as the thermodynamics of such thin film based hydrogen sensors is temperature dependent, and sensors based on this concept require information of the temperature of the sensor in order to correctly determine the hydrogen concentration. The solution to this is typically to provide a standard temperature sensor added to the sensing device. However, temperature sensors are additional devices which increase the complexity and costs of a product, and moreover they are sensitive to magnetic fields which are generally present inside transformers, thereby potentially causing an erroneous hydrogen reading. Therefore, in case of the presence of magnetic fields such as in transformers, solutions are preferred where a part of the thin film structure of the fiber optical sensor itself is used for the temperature determination. The state-of-the art solution to this is addition of a further thin layer, which is used to determine the temperature using physical principles as, for instance, interference and expansion/contraction of the sensor itself. Such a sensor is described in the article “A fiber optic temperature sensor with an epoxy-glue membrane as a temperature indicator”, S. Tao, A. Jayaprakash, Sensors and Actuators B 119 (2006) 615-620. It refers to a fiber optic temperature sensor for the monitoring/detecting of the ambient temperature. This sensor is based on polycyclic aromatic compounds (PAHs) as the temperature indicator, which fluoresce when excited with UV light, wherein the intensity of the fluorescent light is dependent on the temperature. This temperature-dependent behavior of the added fluorescent layer is then used to determine the temperature, which may then be employed in determining the hydrogen concentration from the signal of actual thin film optical hydrogen sensor.
A related principle is described in “A reflective fiber optic temperature sensor using silicon thin film”, J. w. Berthold, S. E. Reed, R. G. Sarkis, Optical Engineering 30(5), 524-528 (1991). The method is based on the change, with temperature, of the intensity of light being reflected from a thin silicon film which is deposited on the end of an optical fiber.
Further, “A Reflectometric Optical Fiber Temperature Sensor”, F. Chiadini, A. Paolillo, and A. Scaglione, IEEE Sensors Journal, vol. 3, no. 1, (2003), describes a reflectometric fiber-optic temperature sensor which is based on replacing the fiber cladding with a temperature sensitive liquid on a short length of the fiber.
In the above described concepts, the extra layer or coating required for temperature determination, additional to the hydrogen-sensitive layer itself, adds cost in the production, requires additional apparatus features for the temperature determination, and thus adds cost in the form of construction and production effort. Moreover, the complexity of the optical sensing system for hydrogen is generally enhanced, and so is probability for failure.
US 2014/374578 A1 discloses a device for the detection and/or quantitative analysis of hydrogen, intended for monitoring an installation. The device comprises a first measuring optical fiber intended to equip the installation, and an optical system optically connected to the first measuring optical fiber.
US 2015/063418 A1 discloses an apparatus for estimating a parameter, which includes an optical fiber sensor configured to be disposed in a downhole location and including at least one sensing location configured to generate measurement signals. A light source is configured to transmit a measurement signal having a wavelength to interrogate a sensing location and cause the sensing location to return a reflected measurement signal indicative of a measured parameter.
US 2009/210168 A1 discloses a signal processing apparatus which has an input for receiving a signal conveying a response from first and second optical components, which are in an optical sensor, to an optical excitation. A signal processing apparatus has a processing entity for processing the response from the first and second optical components to derive information on a hydrogen concentration in the optical sensor.
In view of the above and for other factors, there is a need for the present invention.